Due to the advent of horizontal well drilling and the wide application of hydraulic fracturing, production from gas bearing shales is now profitable and consequently represents a significant supply of natural gas in US. However, the mechanism of gas production in association with the hydraulic fracturing is currently not thoroughly understood. For example, only about 10-20% of the injected water is recovered. Furthermore, despite the success of the fracturing technique in gas shale, estimated average gas recovery rates are still quite low at less than 15%.
The key to understanding these phenomena lies in unraveling the complex chemical-physical property relationships of gas shale formations. Gas shales are characteristically composed of various consolidated clay-sized aluminosilicate minerals mixed with varying amounts of calcite, organic matter, methane through butane gas, and water, and exhibit low porosity (several percent) and permeability (millidarcy to nanodarcy levels along and orthogonal to the bedding plane, respectively). Importantly, the abundance, type, and maturity of total organic carbon (TOC), largely in the form of polymeric kerogen, contained within the shale matrix is expected to exert significant control on gas and fracturing water recovery factors. For instance, the micropore network through which fluid flow occurs is often distributed between both hydrophilic mineral and hydrophobic organic phases, with the latter being more ubiquitous at higher maturities. These conditions directly influence the rock wettability and the porosity/permeability, respectively, which consequently affects the overall type and rate of produced fluids from a well.
TOC abundance and type is generally evaluated in the laboratory by pyrolytic or combustion-based techniques. In Rock-Eval pyrolysis, the effluent produced from heating a sample aliquot under an inert atmosphere is monitored in three stages. In the first stage (known as S1), the temperature is kept isothermal at 300° C., releasing the volatile components. The temperature is then ramped to 550° C. in the second stage (S2), resulting in the thermal cracking of the non-volatile organic matter. The evolved matter from these first two stages is quantified with a flame ionization detector (FID). In the third stage (S3), the amount of CO2 produced from 300-390° C. is measured using a thermal conductivity detector (TCD). In this way, the sum of S1+S2+S3 peaks can be used as a crude metric of TOC content, whereas the relative amounts of hydrogen and oxygen in TOC can be approximated using the S2/(S1+S2+S3) and S3/(S1+S2+S3) ratios, respectively. A more accurate measurement of TOC content and type can be derived from combustion-based elemental analysis. This technique involves a tin-catalyzed high temperature combustion of a sample aliquot that has been pre-treated with acid to remove carbonate minerals, subsequent chromatographic separation of the resulting CO2, N2, H2O, and SO2 species, and ultimate TCD quantification to yield the organic carbon, nitrogen, hydrogen, and sulfur content. The oxygen content is similarly obtained under anoxic reactor conditions. TOC maturity, on the other hand, has been traditionally scaled by (a) petrographic observations on whole rock or kerogen isolates, wherein the reflectance properties of organic macerals—primarily vitrinite—are quantified via optical microscopy, (b) the temperature of maximum S2 product generation in Rock-Eval pyrolysis, and (c) biomarker analysis on petroleum extracts, such as the evolution of higher chain length dominated, odd-over-even alkane distributions to shorter chain length, unimodel series as measured by chromatographic and mass spectrometric analyzers.
However, all of these approaches suffer from being time consuming and destructive to the sample.